1. Field of the Invention
The present invention relates to producing a liquid from a well such as a gas well, an oil well, or water well while maintaining the fluid level in the tubing-casing annulus at a desired level through the interaction of a real-time fluid level detection device with a variable frequency controller connected to an electrical motor operating a subsurface pump. The integration of a real-time fluid level detection device together with a variable frequency controller allows the optimization of well bore inflow with the well outflow provided by the artificial lift system. As an added benefit, the present invention provides for the rapid and relatively easy determination of the fluid level in the tubing-casing annulus, as well as providing a history of the fluid levels and performance history of the artificial lift equipment. The system may be utilized to monitor and record the observed fluid flow, gas flow, the casing pressure, and the tubing pressure. The system may also determine the best fluid level for maximum inflow given the existing well mechanical condition and the reservoir dynamics, such as influence from injection wells or other producing wells.
2. Description of Practices in the Art
It is known that fluids are replenished into a particular well bore at different rates even in the same formation or well field. Such replenishment is impacted by, among other things, the section of reservoir exposed to perforations or slots, any formation damage adjacent to the well bore, and/or the extent of reservoir heterogeneities adjacent to the well bore. Moreover, fluid replenishment into a particular well bore may change over time as a result of changes in reservoir properties resulting from cumulative production, stimulation or reservoir management practices. When a fluid reservoir is initially produced, there may be sufficient reservoir energy to produce the fluids to the ground surface, i.e., the pressure of the fluid reservoir is greater than the hydrostatic pressure exerted by a fluid column which extends from the ground surface to the depth of the reservoir. However, once the reservoir energy depletes to where the reservoir pressure is less than the hydrostatic pressure of the fluid column, some form of artificial lift system is required to bring the reservoir fluids to the ground surface. Such artificial lift systems may include subsurface pumps which are typically installed at the depth of the producing reservoir.
One commonly known artificial lift system utilizes a plurality of rods connected in an end-to-end configuration forming a “rod string.” The rod string is set within a plurality of tubing joints which are likewise connected in an end-to-end configuration forming the “tubing string,” with the reservoir fluids primarily produced up the tubing string. The rod string is utilized to operate a pump set at the bottom of the tubing string. The most commonly used subsurface pump has a plunger which reciprocates up and down within a barrel, where the plunger is connected to the rod string and the rod string is reciprocated by a pumping unit set at the ground surface. Another type of subsurface pump, a progressive cavity pump, has a rotor which is rotated within a stator by the rod string, where the rod string is rotated at the ground surface by an electrical motor coupled to a gear reducer. Electric submersible pumps are also used, where the motor is located downhole and coupled directly to a centrifugal pump. In these installations, no rod string is required. However, the capacities of each of these artificial lift systems—reciprocating rod pumps, progressive cavity pumps, and downhole centrifugal pumps—is capable of being adjusted by utilizing a variable frequency drive to change the speed of the electrical motor operating the system.
With each subsurface pumping system, a dynamic equilibrium is reached where the inflow rate of the reservoir and the outflow rate generated by the artificial lift system are essentially equivalent, except for gas produced through the casing-tubing annulus. However, the inflow rate from the reservoir into the well bore depends upon any backpressure maintained on the reservoir through the well bore. Such backpressure may be imposed by the surface production equipment into which the well produces. Backpressure is also imposed by any standing fluid level within the well bore in the tubing-casing annulus. Ideally, backpressure and the fluid level within the tubing-casing annulus are maintained at a minimum to maximize the pressure differential from the reservoir into the well bore and thus maximize fluid flow into the well bore. However, achieving this maximum inflow requires a corresponding matching outflow to reach a dynamic equilibrium. In other words, to achieve maximum production from a well, the well outflow rate generated by the artificial lift system must match the maximum inflow rate produced from the reservoir to minimize the backpressure exerted by the fluid level.
The preceding discussion suggests that the subsurface pump should be run constantly and/or at a high capacity to keep the level in the well bore as low as possible thus maximizing production. However, this option may be less than ideal because if the outflow produced by the artificial lift equipment exceeds the inflow, several negative results may occur. First, running the pump constantly or at too great a speed may be inefficient because, some of the time, the well may be “pumped off” leaving little fluid in the well bore to be pumped, resulting in wasted energy. Second, running pumping equipment when a well is in a pumped off condition can damage the equipment, resulting in costly repairs. Third, paraffin build up is more pronounced when a well is allowed to pump dry. In a pumped off condition gases are drawn into the well bore, which expand and cool. As the gases cool, paraffin build up is promoted as the hydrocarbons begin plate out on the surfaces of the well bore.
Achieving equilibrium between inflow and outflow is further complicated by changing conditions within the reservoir, which result in changes in inflow performance. Such changes may result from, among other things, the initiation or suspension of a reservoir pressure maintenance program utilizing either gas or water injection, stimulating the well to remove reservoir damage near the well bore, or stimulating injection wells to increase injection rates. The reservoir conditions may also be impacted by the addition of new wells producing from the reservoir or changing production rates in existing wells. Thus, matching inflow performance of the reservoir with the outflow of the artificial lift system can present a moving target and an artificial lift system which maintains a constant outflow is not a preferred solution for a well subject to changes in its inflow performance.
A variety of methods are known for adjusting the outflow performance of an artificial lift system. Systems which utilize reciprocating rod pumps may have adjustments made to the outflow performance by changing the speed of rod reciprocation, changing the length of the pump stroke, or changing the diameter of the subsurface pump. Changing pumping speed and pump stroke for rod pumped wells usually can be accomplished by making adjustments in surface equipment, however changing the pump diameter requires pulling the rod string, pump, and often the tubing string. Changing the speed of rod reciprocation can be done by causing the surface pumping unit to run faster by either changing the sheave size between the prime mover and gear box, or by changing the operational speed of the pumping unit motor. Changing the sheave size requires the shutting down of the pumping unit and can be an involved process requiring a construction crew.
Changing the operational speed of the motor may be accomplished through the use of a variable speed drive unit, or variable frequency drive (“VFD”). If a VFD is combined with a processing unit, various input parameters, including observed fluid levels, may be utilized to arrive at a pumping speed, and thus a particular outflow capacity, which is in dynamic equilibrium with the reservoir inflow performance. Such systems may be used not only with reciprocating rod pumps, but also with rod-operated progressive cavity pumps and downhole submersible pumps.
U.S. Pat. No. 6,085,836, invented by the present inventors, proposed an initial solution to the problem of reaching dynamic equilibrium between reservoir inflow performance and the outflow performance of the artificial lift equipment. The '836 patent is incorporated herein by reference. The '836 patent discloses a method of determining the well fluid level for purposes of adjusting the subsurface pumping time, including controlling pumping time with timers. It is known to use timers to control the pump duty cycle. A timer may be programmed to run the well nearly perfectly if one could determine the duration of the on cycle and off cycle which maintains a dynamic equilibrium between the inflow to the well bore and the outflow generated by the artificial lift equipment.
If real time fluid level information can be obtained, deciding when or how fast to run the pump is relatively straightforward and production can be optimized. Real time fluid level determinations, particularly for deep well systems, have been realized by the implementation of downhole instrumentation such as load cells, transducers or similar devices which acquire downhole pressures (thus fluid levels) and transmit the information to the surface via various means. Unfortunately, these real time downhole systems have been costly and complex to install, unreliable in operation, and costly to repair or service. Although the implementation details will not be discussed here, it is worth noting that these systems, when operating correctly, have proven that significant gains in well production are available when control strategies applying real time fluid level measurement are utilized.
As an alternative to systems which measure downhole pressure, are those systems which utilize acoustic energy to ascertain the depth of the fluid level by generating an acoustic wave at the surface and detecting the return signal to calculate the depth to fluid. One such system uses a one-shot measurement. The one-shot measurement will use a sonic event, such as firing a shotgun shell, to generate the acoustic signal. Another system utilizes charges from a nitrogen tank to generate sonic events. However, in either of the foregoing systems the production of the well must be shut down before initiating the sonic event and monitoring the corresponding return signals.